In the oil and gas industry, seismic prospecting techniques are commonly used to aid in the search for and evaluation of subterranean hydrocarbon deposits. In seismic prospecting, a seismic source is used to generate a physical impulse known as a "seismic signal" that propagates into the earth and is at least partially reflected by subsurface seismic reflectors (i.e., interfaces between underground formations having different acoustic impedances). The reflected signals (known as "seismic reflections") are detected and recorded by seismic receivers located at or near the surface of the earth, in an overlying body of water, or at known depths in boreholes, and the resulting seismic data may be processed to yield information relating to the subsurface formations.
Seismic prospecting consists of three separate stages: data acquisition, data processing, and data interpretation. The success of a seismic prospecting operation depends on satisfactory completion of all three stages.
The seismic energy recorded by each seismic receiver during the data acquisition stage is known as a "seismic data trace." During the data processing stage, the raw seismic data traces are refined and enhanced so as to facilitate the data interpretation stage. For example, one common method for enhancing seismic data traces is through the common-midpoint (CMP) stacking process. As will be well known to persons skilled in the art, the "midpoint" for a seismic data trace is the point midway between the source location and the receiver location for that trace. According to the CMP method, the recorded seismic data traces are sorted into common-midpoint gathers each of which contains a number of different seismic data traces having the same midpoint but different source-to-receiver offset distances. The seismic data traces within each CMP gather are corrected for statics (i.e., the effects of variations in elevation, weathered layer thickness and/or velocity, and reference datum) and normal moveout (i.e., the variation of traveltime with respect to source-to-receiver offset) and are then summed or "stacked" to yield a stacked data trace which is a composite of the individual seismic data traces in the CMP gather. Typically, the stacked data trace has a significantly improved signal-to-noise ratio compared to that of the unstacked seismic data traces in the CMP gather.
Stacked data traces for a series of CMP locations falling along a particular survey line may be displayed side-by-side to form a stacked seismic section which simulates a zero-offset seismic section (i.e., a seismic section where every trace is the result of a coincident source and receiver). Thus, a stacked seismic section is a representation, in two-way seismic signal traveltime, of a vertical cross-section of the earth below the survey line in question. Stacked seismic sections are used in the data interpretation stage to predict subsurface stratigraphy.
Typically, the phase characteristics of seismic data traces recorded during the data acquisition stage are "minimum-phase," or nearly so. In other words, at the instant that a seismic signal reaches a subsurface reflector, a reflected signal begins to form. As the downgoing seismic signal rises in strength, the upgoing reflected signal also rises in strength. Similarly, as the downgoing seismic signal begins to decline in strength, the upgoing reflected signal also begins to decline. The result of this process is that in a conventional stacked seismic section, each subsurface reflector is marked by the leading edge of a seismic pulse or "wavelet."
Because a seismic data trace represents a convolution of many overlapping reflections, it is often difficult to clearly identify the leading edge of a seismic wavelet. It would facilitate interpretation of seismic data if the subsurface reflectors were marked by peaks or troughs in the data rather than by a rising or falling edge of a seismic wavelet because peaks and troughs are easier to identify. A procedure known as "zero-phase processing" is commonly used in the industry to accomplish this result. In zero-phase processing, the minimum-phase seismic wavelet embedded in the seismic data is converted to a zero-phase wavelet. Zero-phase wavelets are symmetrical, and the time scale is shifted so that the center of the wavelet indicates the arrival time. In other words, the center of a zero-phase wavelet coincides with the subsurface seismic reflector that caused the reflection. The conversion to zero-phase is preferably performed on the individual seismic data traces within a CMP gather prior to stacking; however, the conversion may also be performed after stacking has occurred. See, e.g., Sheriff, R. E. and Geldart, L. P., Exploration Seismology, Volume 1: History, theory, & data acquisition and Volume 2: Data-processing and interpretation, sections 4.3.4, 8.1.4, and 10.6.6d, Cambridge University Press, 1982. The result of this process is a zero-phase seismic section in which the subsurface reflectors generally are marked by peaks and/or troughs in the stacked data traces.
Another advantage of zero-phase processing is that the resulting zero-phase seismic data traces typically have better seismic resolution (i.e., the ability to distinguish two reflectors which are close together) than the seismic data traces recorded during the data acquisition stage. See Schoenberger, M., "Resolution comparison of minimum-phase and zero-phase signals," Geophysics, Vol. 39, No. 6, pp. 826-833, December 1974. Accordingly, converting the recorded seismic data traces to zero-phase data traces permits identification and interpretation of shorter geologic intervals than is possible with conventional seismic data processing.
For the reasons set forth above, zero-phase processing results in a zero-phase seismic section that is easier to interpret than a routine stacked seismic section. However, zero-phase processing does not resolve all seismic data interpretation problems. For example, although zero-phase seismic data has better seismic resolution than conventional seismic data, seismic resolution may still be a problem for thin geologic features. Many subsurface geologic features of interest to the petroleum industry are from about five to about 50 feet in thickness. The cycle of a seismic pulse is typically sinusoidal and from about 80 to about 800 feet in length. Because a cycle consists of both a positive phase and a negative phase, the approximate resolution of a typical seismic pulse is from about 40 to about 400 feet. A seismic reflection is generated each time the seismic pulse encounters an impedance boundary. When the impedance boundaries are closer together than the resolution of the seismic pulse, the seismic reflections overlap, as noted above. Thus, the presence of an impedance boundary of interest may appear as only a small anomaly on the sinusoidal seismic data trace, such as a subdued peak or a departure from sinusoidal (i.e., a bend or kink in the data). Failure to identify and interpret these anomalies can result in erroneous conclusions regarding the subsurface stratigraphy.
Thus, there is a need for a method for enhancing seismic data to make subtle geologic features more easily identifiable. Such a method should permit the identification and interpretation of geological features marked only by an anomaly in the zero-phase data. The present invention satisfies this need.